Method for injecting low salinity water

ABSTRACT

Methods, apparatuses and computer readable instructions for determining the effectiveness of, and for performing, a low salinity waterflood. An ion diffusion distance value is determined based on the rate of diffusion of ions within the rock of a reservoir and the residency time of floodwater within the reservoir. The thickness of the layers of the reservoir are compared to this ion diffusion value to determine the effectiveness of performing a low salinity waterflood and also to enable the effective control of a waterflood and to assist in the determination of locations of wells.

FIELD OF INVENTION

This invention relates to systems and methods for determining theeffectiveness of, and for performing, a low salinity waterflood on ahydrocarbon-bearing reservoir. In particular this invention relates tosystems and methods to be used when the reservoir comprises relativelypermeable layers interbedded with relatively impermeable layers andwhere the relatively impermeable layers have a relatively highconcentration of ions compared to that of the relatively permeablelayers when the low salinity water is present therein.

BACKGROUND OF THE INVENTION

A hydrocarbon-bearing reservoir typically takes the form of a pluralityof sandstone layers interbedded with shale layers. The sandstone layershave sufficient porosity and permeability to store and transmit fluids(for example oil and water). Typically the oil is held in pores of therock formation. By contrast the shale layers are relatively impermeableto these fluids.

It is known that only a portion of the total crude oil present in areservoir can be recovered during a primary recovery process, thisprimary process resulting in oil being recovered under the naturalenergy of the reservoir. Secondary recovery techniques are thereforeoften used to force additional oil out of the reservoir. One example ofa secondary recovery technique is to directly replace the oil with adisplacement fluid (also referred to as an injection fluid), usuallywater or gas.

Enhanced oil recovery (EOR) techniques may also be used. The purpose ofsuch EOR techniques is not only to restore or maintain reservoirpressure (as is done by typical secondary recovery techniques), but alsoto improve the displacement of the oil from the reservoir, therebymaximizing the recovery of oil from the reservoir and minimizing theresidual oil saturation of the reservoir (the volume of oil present inthe reservoir).

“Waterflooding” is one of the most successful and extensively usedsecondary recovery methods. Water is injected, under pressure, intoreservoir rock layers via injection wells. The injected water acts tohelp maintain reservoir pressure, and sweeps the displaced oil ahead ofit through the rock towards production wells from which the oil isrecovered. The water used in waterflooding is generally saline waterfrom a natural source (such as seawater) or may be produced water (i.e.water that is separated from the crude oil at a production facility).

In addition to waterflooding using saline water, it is possible to uselower salinity injection water (for example, brackish water such asestuarine water, or fresh water such as river water, or lake water). Theuse of low salinity waterflooding can increase the amount of oilrecovered compared to that recovered using high salinity water since thelow salinity water is better able to displace the oil from thereservoir.

Preferably, the water used in a low salinity waterflood typically has atotal dissolved solids (TDS) content in the range of 500 to 12,000 ppm.It is also preferred that the ratio of the total multivalent cationcontent of the low salinity injection water to the multivalent cationcontent of the formation water that is present in the sandstone layersof the reservoir is less than 1. The use of a low salinity waterflood isparticularly beneficial when oil that is present in the sandstone layersof the reservoir (typically oil that is adhering to the surface of thesandstone rock) is a medium or light crude having an American PetroleumInstitute (API) gravity of at least 15°, preferably at least 20°, andfor example an API gravity in the range of 20° to 60°.

During a low salinity waterflood, the low salinity injection water isinjected into and flows through the sandstone layers of the reservoir.By contrast little water flows through the relatively impermeable shalelayers. Thus, the oil is produced from the high permeability sandstonelayers while insignificant amounts of oil are produced from the lowpermeability shale layers. Indeed, shale is often so impermeable thatthe interbedded shale layers of the reservoir remained unsaturated withoil during migration of oil from a source rock into the sandstone layersof the reservoir. Instead, the shale layers are saturated with connatewater that is typically of high salinity.

It has now been found that for reservoirs having interbedded sandstoneand shale layers, the incremental oil recovery effect that is achievedusing low salinity waterflooding may be reduced. This is due to thediffusion of ions from higher salinity connate water present in the porespace of the shale layers into the low salinity water that is flowingthrough the adjacent sandstone layer of the reservoir. This reduction inrecovery is of particular concern when large volumes of high salinityconnate water reside in shale layers that are interbedded with thesandstone layers of the reservoir and when the interbedded sandstonelayers are relatively thin.

The dominant mass transfer mechanism from the connate water of the shalelayers to low salinity water that is flowing through the adjacentsandstone layers of a reservoir is molecular diffusion, whereby saltions diffuse from the connate water in the shale layer to the lowsalinity water in the sandstone layer. Typically, the moleculardiffusion of salt ions from the shale layer occurs in a directionsubstantially orthogonal to the direction of flow of the low salinitywater through the adjacent sandstone layer (i.e. in the direction of theconcentration gradient).

The diffusion of the salt ions from higher salinity connate waterpresent in the pore space of the shale layers can reduce theeffectiveness of a low salinity waterflood by increasing the salinity ofthe water flowing through the sandstone layers. It is therefore anobject of the invention to improve the effectiveness of low salinitywaterflooding.

SUMMARY OF INVENTION

In accordance with at least one embodiment of the invention, methods,devices, systems and software are provided for supporting orimplementing functionality to provide effective waterflooding of areservoir. This is achieved by a combination of features recited in eachindependent claim. Accordingly, dependent claims prescribe furtherdetailed implementations of the present invention.

According to a first aspect of the invention there is provided acomputer-implemented method for determining the effectiveness ofperforming a low salinity waterflood on a hydrocarbon-bearing reservoir,wherein the reservoir comprises relatively permeable layers interbeddedwith relatively impermeable layers and is penetrated by an injectionwell and a production well, the low salinity waterflood comprisinginjecting low salinity water into the hydrocarbon-bearing reservoir fromthe injection well whereby to pass through the relatively permeablelayers of the reservoir from the injection well to the production well,and wherein the relatively impermeable layers have a relatively highconcentration of ions compared to that of the relatively permeablelayers when the low salinity water is present therein, the methodcomprising: deriving an ion diffusion distance value from: a diffusioncoefficient indicative of a rate of diffusion of ions through therelatively permeable layers when the low salinity water is presenttherein; and a residence time value indicative of the time required forthe low salinity water to pass from the injection well to the productionwell through the reservoir; comparing the thickness of the relativelypermeable layers to the derived ion diffusion distance value; and usinga result of the comparison to generate an output indicative of theeffectiveness of performing a low salinity waterflood.

Performing a low salinity waterflood requires, amongst other things, asignificant quantity of low salinity water, which is generally notavailable in abundance. This means that it is important to be able todetermine a measure of how effective the low salinity waterflood willbe. Such a determination may be made by performing a fine scalereservoir simulation; however this requires a large amount of computingresources to perform, typically many hours of processing using amainframe or ‘supercomputer’. By deriving the ion diffusion distancevalue and comparing this to the thickness of the layers in thereservoir, an output indicative of the effectiveness of performing a lowsalinity waterflood can be generated using significantly reducedcomputing resources. The output can ensure that only effective lowsalinity waterfloods are performed, and therefore that the limitedsupply of low salinity water is used to maximum effect.

According to a second aspect of the invention there is provided acomputer-implemented method of controlling a low salinity waterflood fora hydrocarbon-bearing reservoir, wherein the reservoir comprisesrelatively permeable layers interbedded with relatively impermeablelayers and is penetrated by an injection well and a production well, thelow salinity waterflood comprising injecting low salinity water into thehydrocarbon-bearing reservoir from the injection well whereby to passthrough the relatively permeable layers of the reservoir from theinjection well to the production well, and wherein the relativelyimpermeable layers have a relatively high concentration of ions comparedto that of the relatively permeable layers when the low salinity wateris present therein, the method comprising: deriving a target velocitybased on: a diffusion coefficient indicative of a rate of diffusion ofions through the relatively permeable layers when the low salinity wateris present therein; an interwell distance between the injection well andthe production well; and a value indicative of a thickness of therelatively permeable layers; and transmitting the derived targetvelocity to a control unit of an injection well.

As described above, it is important to ensure that a low salinitywaterflood will be effective. While the effectiveness of a low salinitywaterflood increases with the velocity of the water, it is generally notpossible, or desirable to maximize this velocity. Consequently, for anefficient waterflood to be performed, a balance needs to be foundbetween the velocity of the floodwater, and the amount of hydrocarbonswhich are recovered in the waterflood. This balance can be achieved bydetermining a target velocity and using this target velocity to controlthe injection into the reservoir and thus control the velocity of thewaterflood.

According to a third aspect of the invention there is provided acomputer-implemented method of determining locations of at least oneproduction well and at least one injection well for ahydrocarbon-bearing reservoir, wherein the reservoir comprisesrelatively permeable layers interbedded with relatively impermeablelayers and is to be penetrated by the at least one injection well and atleast one production well, wherein the injection well is arranged toprovide a low salinity waterflood comprising injecting low salinitywater into the hydrocarbon-bearing reservoir from the injection wellwhereby to pass through the relatively permeable layers of the reservoirfrom the injection well to the production well, and wherein therelatively impermeable layers have a relatively high concentration ofions compared to that of the relatively permeable layers when the lowsalinity water is present therein, the method comprising: calculating aninterwell distance value based on: a diffusion coefficient indicative ofa rate of diffusion of ions through the relatively permeable layers whenthe low salinity water is present therein; a value indicative of athickness of the relatively permeable layers; and a velocity at whichthe low salinity water passes through the reservoir; and using theinterwell distance value to determine the locations of the at least oneinjection well and the at least one production well such that theinterwell distance between the said at least one injection well and atleast one production well is less than said interwell distance value.

It requires significant time and resources to drill a well in anoilfield, therefore it is desirable to ensure that the maximum distanceis present between wells. However there are disadvantages of having sucha large distance, one of which is that, should a low salinity waterfloodbe performed, the effectiveness will reduce with increasing interwelldistance. In order to achieve a balance, this aspect of the inventioncalculates an interwell distance value, based on the parameters whichwill affect a low salinity waterflood, and uses this value to determinethe positioning of the wells.

According to further aspects of the invention there are provided systemsand apparatuses for performing the methods described above and computerreadable storage media storing computer readable instructions thereonfor execution on a computing system to implement the methods describedabove.

Further features and advantages of the invention will become apparentfrom the following description of preferred embodiments of theinvention, given by way of example only, which is made with reference tothe accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

Systems and methods will now be described as embodiments of the presentinvention, by way of example only, with reference to the accompanyingfigures in which:

FIG. 1 shows a schematic diagram of an oil recovery system and areservoir in respect of which embodiments of the invention areapplicable;

FIG. 2 shows schematic diagram of a processing system in whichembodiments of the invention may operate;

FIG. 3 shows a plot showing the diffusion of ions;

FIG. 4 shows a computer implemented method of determining theeffectiveness of performing a low salinity waterflood according to anembodiment of the invention;

FIG. 5 shows a computer implemented method of controlling a low salinitywaterflood according to an embodiment of the invention;

FIG. 6 shows a computer implemented method of determining locations ofthe production injection wells according to an embodiment of theinvention; and

FIG. 7 shows a plot showing results obtained by an embodiment of theinvention compared to results obtained by fine-scale reservoirsimulation.

DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS OF THE INVENTION

FIG. 1 is a schematic block diagram showing a simplified representationof a crude oil recovery system 100. Within the system a multi-layerreservoir is present. In this example, the reservoir comprises a seriesof interbedded permeable and impermeable layers. The permeable layers(in this example sandstone) bear oil in the pore spaces within the rock,and are referenced 102, 104 and 106. The impermeable layers (in thisexample shale) generally do not bear oil, and are referenced 108, 110,112 and 114. Above the top impermeable layer 108 is shown a generalizedsurface layer 116 which may comprise multiple, non-oil bearing layers,and (if the reservoir is offshore) a layer of seawater. The compositionof these layers is not relevant to this example.

The permeable and impermeable layers make up the reservoir. Penetratingthe reservoir is an injection well, comprising a control station 118 anda well bore 120; and a production well, comprising a control station 122and a well bore 124. The injection and production wells are separated bya distance L as shown. (Typically there are many more wells than the twoshown here; however two are shown in this exemplary embodiment forsimplicity).

Each of the permeable layers (102, 104 and 106) in the reservoir has anassociated thickness (w₁, w₂ and w₃ respectively). As can be seen fromthe figure, each layer has a different thickness. In addition, it can beseen that layer 102 has a varying thickness, being of thickness w₁ atthe injection well end, and of a narrower thickness w₁′ at theproduction well end. This change in thickness will be referred to later.

When in use for a low salinity waterflood, the injection well injectslow salinity water as an injection fluid under pressure into thereservoir. The low salinity water flows along each of the permeablelayers 102, 104 and 106 as shown by the arrows. The low salinity waterforces the oil in the reservoir ahead of it causing the oil to be forcedfrom the reservoir into the well bore of the production well (againshown by the arrows). From there, the pressure of the reservoir,optionally aided by pumps located in the well bore of the productionwell, lifts the oil and water received from the reservoir up to thesurface where it can be stored, refined and used.

During a low salinity waterflood, the low salinity injection water maybe passed continuously into the injection well and into the sandstonelayers of a reservoir. However, it is preferred that the low salinityinjection water is passed in one or more portions (hereinafter referredto as “slugs”) of a controlled volume, which is normally expressed interms of the “pore volume” or PV. The term “pore volume” is used hereinto mean the volume of the pore space in the sandstone rock layersbetween an injection well and a production well and may be readilydetermined by methods known to the person skilled in the art. Suchmethods may include measuring the time taken for a tracer to passthrough the sandstone layers from the injection well to the productionwell. The swept volume is the volume swept by the injection wateraveraged over all flow paths between the injection well and productionwell.

Although, it is possible to continue to inject the low salinityinjection water into the reservoir, typically the pore volume of theslug of low salinity injection water is minimized since there may belimited injection capacity for the low salinity injection water owing tothe need to dispose of produced saline water (which is disposed of byinjection into the reservoir). Thus, the volume of the slug of lowsalinity injection water is preferably less than 1, and may for examplebe less than 0.5 PV. Therefore, the slug of low salinity injection watermay have a pore volume in the range of 0.2-0.9 PV, and more preferablymay be in the range of 0.3-0.45 PV.

After injection of a slug of low salinity injection water, a drive (orpost-flush) water of higher multivalent cation content and/or higher TDS(i.e. high salinity), may be injected into the reservoir. For example,the drive water may have a total dissolved solids (TDS) of at least30,000 ppm, for example, 30,000 to 50,000 ppm and a multivalent cationcontent of at least 350 ppm. By contrast the water in the low salinityslug typically has a TDS content in the range of 500 to 12,000 ppm. Sucha low salinity slug may have a multivalent cation content of less than40 ppm.

The volume of the slug of low salinity injection water may be small yetthe slug is still capable of releasing substantially all of the oil thatcan be displaced from the surface of the pores of the sandstone rockunder the reservoir conditions. Generally, the volume of the slug of lowsalinity injection water is at least 0.2 PV, as a slug of lower volumetends to dissipate in the sandstone rock and may not result inappreciable incremental oil production. It has also been found thatwhere the volume of the low salinity injection water is at least 0.3 PV(and preferably at least 0.4 PV), the slug tends to maintain itsintegrity within a sandstone rock (that is, it does not disperse withinthe rock) and therefore continues to sweep displaced oil towards aproduction well. Thus, the incremental oil recovery for a reservoir thatcomprises sandstone layers approaches a maximum value with a slug of atleast 0.3-0.4 PV. There is little additional incremental oil recoverywith higher volume slugs.

Where the slug of low salinity injection water has a volume of less than1 PV (that is the low salinity slug will not fill the reservoir, andwill need to have a driving injection fluid, typically high salinitywater, injected behind it), the drive water will ensure that thefractional pore volume slug of low salinity water (and hence thereleased oil) is swept through the reservoir to the production well. Inaddition, the injection of the drive water may be required to maintainthe pressure in the reservoir. Typically, the drive water has a greatervolume than the slug of low salinity injection water.

Although the slug of low salinity water that is injected into theoil-bearing sandstone layers of the reservoir is only a fraction of thepore volume, the slug generally remains intact within the formation andcontinues to sweep displaced oil towards a production well. Withoutwishing to be bound by any theory, it is believed that although there isdispersive (diffusive) mixing between the higher salinity drive waterand the low salinity water at the tail (back) of the slug there islittle dispersive (diffusive) mixing between the low salinity water andthe formation water at the front of the slug. The reason why there islittle diffusive mixing between the low salinity water and the formationwater at the front of the slug is that there is an ion exchange reactionoccurring between the monovalent cations in the low salinity water slugand the multivalent cations (predominantly divalent cations) that arebinding the residual oil to the rock surface. This means that the slugattains a steady state arising from the fact that the velocities of theion concentrations are lower in the leading edge than in the trailingportions (because of ion exchange driven adsorption at the leadingedge), and thus the slug sharpens on propagation. In mathematical terms,this arises because the diffusion equation for mixing of the lowsalinity water with the formation water that is present in the sandstonelayers (which has diffusion terms for the concentrations of theindividual ions in the low salinity water and the individual ions in theformation water that are dependent upon distance and time) is balancedby the addition of an extra mathematical term that takes into accountion exchange between the low salinity water and the rock (sorption). Forthese reasons, the slug of low salinity water remains intact (does notsubstantially mix with the formation water) as the slug is forcedthrough the sandstone layers by the subsequently injected highersalinity drive water.

During a low salinity waterflood, the extent of diffusion of ions fromthe high salinity water trapped in the impermeable layers into the lowsalinity water, and hence the impact of the resulting increase insalinity of the injected low salinity water on the incremental oilrecovery is dependent upon one or more of the following parameters:

1. the flow rate of the low salinity water through the permeable(sandstone) layers of the oil reservoir (generally expressed as asuperficial velocity, v);

2. the interwell distance, L, between the injection well that is used toinject the low salinity water into the oil reservoir and the productionwell that is used to produce oil from the oil reservoir;

3. salt diffusion coefficients in the impermeable (shale) layers;

4. the concentration gradient between the dissolved salts that arepresent in the connate water of a shale layer and the dissolved saltsthat are present in the low salinity water that is flowing through theadjacent sandstone layer;

5. the thickness of the interbedded shale layers of the oil reservoir;

6. the thickness of the interbedded sandstone layers of the oilreservoir;

7. the fraction of the total sandstone reservoir made of thininterbedded and hydraulically connected sandstone layers within areservoir.

The flow rate (v) and the interwell distance (L) define the ‘residencetime’, t, of the low-salinity water in the sandstone layer(s) of thereservoir and therefore the time available for salt ions to diffuse froma shale layer into the low salinity water that is flowing through anadjacent sandstone layer of the reservoir. Thus, the residence time, t,may be defined as L/v wherein L is the interwell distance between theinjection and production wells and v is the superficial velocity of thelow salinity water in the sandstone layers of the reservoir. If theresidence time of the low salinity water in the sandstone layer of theoil reservoir is low, there may be little salt diffusion from the shalelayer into the low salinity water and hence an insignificant increase inthe total dissolved solids (TDS) content of the low salinity waterand/or its multivalent cation concentration. Conversely, if theresidence time of the low salinity water in the reservoir is high, theremay be significant salt diffusion into the low salinity water and asignificant increase in TDS content of the low salinity water and/or itsmultivalent cation concentration.

As discussed above, the flow rate of the low salinity water through thesandstone layers of the reservoir may be expressed as a superficialvelocity, v, which is defined as the volumetric flow rate of the lowsalinity water through the sandstone layers of the reservoir (which canbe determined from the volumetric injection rate) divided by thecross-sectional area of the sandstone layers. As an approximation, thesuperficial velocity corresponds to the frontal advance rate of the lowsalinity water in the reservoir.

The superficial velocity of the low salinity water in the sandstonelayers of a reservoir is typically in the range of 0.05 to 5 feet/day(0.015 to 1.5 meters/day) and more often is in the range of 1 to 4 feetper day (0.3 to 1.2 meters/day). However, as discussed below, thesuperficial velocity may be limited by the permeability of the sandstonerock or the injectivity of the reservoir.

The interbedded sandstone layers of a reservoir may be isolated from oneanother such that there is a single flow path for the low salinity waterthrough each sandstone layer from the injection well to the productionwell. Alternatively, the sandstone layers of a reservoir may behydraulically interconnected owing to fractures or faults in the shalelayers or to the shale layers not being contiguous with the sand layersalong the entire interwell distance between the injection well and theproduction well. In this situation, the low salinity injection waterfinds many flow paths through the hydraulically connected sandstonelayers of the reservoir and it is the average superficial velocity ofthe low salinity water through the sandstone layers that is determined.

Typically, each of the sandstone layers of the reservoir has apermeability of at least 1 millidarcy, and more often at least 500millidarcies. Generally, the permeability of each of the sandstonelayers of the reservoir is in the range of 1 to 1000 millidarcies. Thepermeability of the interbedded sandstone layers of the reservoir may bedetermined, for example, from measurements made on core samples takenfrom the reservoir using standard techniques. The superficial velocityfor the low salinity water may vary with varying permeability of thesandstone rock.

The superficial velocity of the low salinity water through the sandstonelayers of the reservoir may also be dependent upon the injectivity ofthe reservoir. The injectivity of the reservoir refers to the rate andpressure at which injection fluids can be injected into a reservoir froman injection well without hydraulically fracturing the reservoir. Thus,the pressure in the injection well should be above the reservoirpressure but below the pressure at which fractures start to be inducedin the reservoir rock. The fracture induction pressure will be reservoirspecific and can be readily determined using techniques well known tothe person skilled in the art. Depending on the reservoir pressure andthe fracture induction pressure, the injection pressure of the lowsalinity water may be in the range of 6,500 to 150,000 kPa absolute, andmore specifically, 10,000 to 100,000 kPa absolute (100 to 1000 barabsolute). Thus, the superficial velocity for the low salinity water maybe increased by increasing the injection pressure and hence the rate atwhich the low salinity water is injected into the reservoir.

In the example system shown in FIG. 1 there is only one injection welland one production well; however, in other embodiments there may be morethan one injection well and more than one production well in thereservoir. The wells may be located on land or may be located offshore.

On land, there may be many different spatial arrangements between theinjection wells and production wells of a reservoir. For example,injection wells may be located around a production well. Alternativelythe injection wells may be in two or more rows between each of which arelocated production wells. However, irrespective of the spatialarrangements of the wells it is generally the case that the interwelldistance L between any injection well and its associated productionwell(s) is less than 3000 feet. Typically, the interwell distance is inthe range of 1000 to 2000 feet. Decreasing the interwell distance Lbetween an injection well and its associated production wells reducesthe residence time of the low salinity water in the sandstone layers ofthe reservoir.

Offshore, there are typically fewer production wells and injection wellsresulting in a larger interwell distance L of, for example, 3000 feetthereby reducing the ability of an operator to control the residencetime t of the low salinity water in the sandstone layers of thereservoir. Accordingly, it may be necessary to select a reservoir for alow salinity waterflood dependent upon one or more of the otherparameters listed above.

Embodiments of the invention provide computer systems, and computerimplemented methods which may be used to assist in the performing of alow salinity waterflood as described above with reference to FIG. 1. Todo this, embodiments of the invention may include a computer systemrunning low salinity waterflooding (LSW) software components whichenable the system to:

determine the effectiveness of performing a low salinity waterflood inthe reservoir;

control a low salinity waterflood within the reservoir;

determine an estimate for the recovery of hydrocarbons for a lowsalinity waterflood performed in the reservoir; and

determine locations of the production and injection wells according toan embodiment of the invention.

The computer system may be located in a planning and control centre(which may be located a substantial distance from the reservoir,including in a different country). Alternatively, the computer systemmay be part of the control systems of the reservoir, such as controlstations 118 and 122 as shown in FIG. 1. The LSW software components maycomprise one or more applications as are known in the art, and/or maycomprise one or more add-on modules for existing software.

A schematic block diagram showing such a computer system will now bedescribed with reference to FIG. 2. The computer system 200 comprises aprocessing unit 202 having a processor, or CPU, 204 which is connectedto a volatile memory (i.e. RAM) 206 and a non-volatile memory (such as ahard drive) 208. The LSW software components 209, carrying instructionsfor implementing embodiments of the invention, may be stored on thenon-volatile memory 208. In addition, CPU 204 is connected to a userinterface 210 and a network interface 212. The network interface 212 maybe a wired or wireless interface and is connected to a network,represented by cloud 214. Thus the processing unit 202 may be connectedwith sensors, databases and other sources and receivers of data throughthe network 214.

In use, and in accordance with standard procedures, the processor 204retrieves and executes the LSW software components 209 stored in thenon-volatile memory 208. During the execution of the LSW softwarecomponents 209 (that is when the computer system is performing theactions described above) the processor may store data temporarily in thevolatile memory 206. The processor 204 may also receive data (asdescribed in more detail below), through user interface 210 and networkinterface 212, as required to implement embodiments of the invention.For example, data may be entered by a user through the user interface210 and/or received from e.g. a remote sensor in a production wellthrough the network 214 and/or may be retrieved from a remote databasethrough the network 214.

These data may be generated and/or stored in a number of ways known tothe skilled person. For example diffusion coefficients (described below)may be determined in a laboratory from a core sample relating to thereservoir (using well known processes). Once determined, this data maybe actively sent to the processing unit 202, or stored in a database tobe retrieved as required by the processing unit 202. Alternatives willbe readily apparent to the skilled person.

Having processed the data, the processor 204 may provide an output viaeither of the user interface 210 or the network interface 212. Ifrequired, the output may be transmitted over the network to remotestations, such as the control station for an injection well. Suchprocesses will be readily apparent to the skilled person and willtherefore not be described in detail.

Examples of the computer implemented methods by which the computersystem described above may operate to implement embodiments of theinvention will be described below; however, to put these methods intocontext, we will now describe some background information relating tothe diffusion of ions into low salinity water flowing through areservoir.

Ions (for example salt ions) may diffuse from a shale layer into anadjacent interbedded sandstone layer relatively slowly, compared to atypical residence time t for the low salinity water in the sandstonelayers of the reservoir. Consequently, the concentration gradient, andtherefore the direction of the diffusion in the layers can be consideredto be substantially perpendicular to the shale-sandstone boundary, and,as such, the diffusion can be considered to be one dimensional.

In addition, the shale layers can be considered to be of sufficientsize, and to have a sufficiently high concentration of ions that theycan be modelled as an unlimited source of ions. To put this another way,the slug of low salinity water represents only a small fraction of thevolume of the connate water in the shale layers. A consequence of thisis that the concentration of ions at the boundary between the shale andsandstone can be considered to be constant.

Finally, the sandstone layer can be considered a semi infinite medium;that is; the portion of the layer concerned is bounded on one side bythe shale, but extends to infinity from there. This is an approximation,since the sandstone layer will be bounded on the other side (most likelyby another shale layer), however it is valid for the examples given.

An analytic expression for the one dimensional diffusion of ions from aconstant composition source into a semi-infinite porous medium of lowpermeability (e.g. from the shale to the sandstone rock) is given by thefollowing one dimensional solution to Fick's law:

$\begin{matrix}{\frac{C(z)}{C_{0}} = {{erfc}\left\lbrack \frac{z}{2\sqrt{D_{a}t}} \right\rbrack}} & \left( {{Equation}\mspace{14mu} 1} \right)\end{matrix}$

where z is distance (depth) within the sandstone measured from theboundary surface of the sandstone and the shale, C₀ is the concentrationof the ion at z=0 (i.e. the concentration in the shale layer), D_(a) isthe apparent diffusivity of ions within the sandstone, t is time andC(z) is the concentration of the diffusing ion in the porous medium at adepth of z.

FIG. 3 shows a plot of C(z)/C₀ against distance (z). Five lines areshown, each curve being constructed using different values of 2√D_(a)t.It can be seen from FIG. 3, the concentration decreases with depth. Inaddition, the longer the residency time (proportional to L/v), thegreater the diffusion.

As can be seen, to minimize the extent of the diffusion, it is desirableto have a short residence time t. As a consequence, it is desirable touse a small interwell distance L and a high superficial velocity v.However, this may be difficult to achieve for both economic andtechnical reasons. For example, in offshore locations, the cost ofdrilling additional wells to achieve the desired smaller interwelldistances may be prohibitively expensive. To overcome these problems, itis desirable to be able to identify conditions under which a lowsalinity water flood will be effective, and to determine theeffectiveness of any low salinity waterflood that might be performedunder such conditions.

Referring to Equation 1, it can be seen that at a value of z=2√D_(a)t,the concentration ratio (C/C₀) has a value of approximately 0.16.Therefore, the distance d=2√D_(a)t may be regarded as the “penetrationdistance” (d), which represents the time-dependent distance within which87% of the diffusing ions are present. Since the residence time t takesthe value of L/v where L and v are the interwell distance and thesuperficial velocity of the waterflood respectively, the penetrationdepth d can be rewritten as:

$\begin{matrix}{d = {2\sqrt{\frac{D_{a}L}{v}}}} & \left( {{Equation}\mspace{14mu} 2} \right)\end{matrix}$

To calculate a measure of the effectiveness of a low salinitywaterflood, the penetration depth can be used to calculate a “boundarylayer” thickness x. This boundary layer represents the portion of eachsandstone layer which is strongly affected by the diffusion of ions intothe sandstone layer from the surrounding shale layer. Inside theboundary layer, it is assumed that there is no incremental recovery ofthe oil (that is, there is no additional recovery of oil from theboundary layer when compared to a high salinity waterflood). Conversely,outside the boundary layer, the diffusion of the ions is assumed to haveno effect on the low salinity waterflood.

It will be apparent that the boundary layer increases in thickness asthe distance from the injection well increases. The thickness will beeffectively zero at the injection well (since there has been noopportunity for the ions to diffuse into the low salinity water). Bycontrast the thickness of the boundary layer will be at a maximum at theproduction well. This average thickness of the boundary layer (x) can becalculated from the penetration depth (d) as derived from equation 2 as:

$\begin{matrix}{x = {{Ad} = {2A\sqrt{\frac{D_{a}L}{v}}}}} & \left( {{Equation}\mspace{14mu} 3} \right)\end{matrix}$

In equation 3, the empirical constant A can be varied to tune theequation, D_(a) and L may be known and relatively constant. The velocityv may be a measure of the superficial velocity through the reservoir;however this is not a requirement, and any appropriate velocity measuremay be used. Normally, there will be a boundary layer at the top andbottom of a sandstone layer interbedded between the shale layers.

Typically, A will have a value of 0.5 (assuming the boundary layer growsuniformly from the injection to the production well), however othervalues may be used. For example, if it is found that a particularreservoir is strongly affected by diffusion of ions, or that theconcentration of ions in the shale layers is unusually high, A may beincreased to have a value of e.g. 1 or 2. Appropriate values of A may befound empirically by the skilled person, for example by comparingdifference simulation results to the results obtained using embodimentsof the invention.

The superficial velocity v may be varied by changing the injectionpressure, and consequently the value of v to be used in this equationmay be varied in dependence on other factors. For example, the maximumsuperficial velocity which may be used through the reservoir may belimited by, for example, the maximum injection pressure which may beused without hydraulically fracturing the reservoir, or the maximumsuperficial velocity which may be economically possible. In someembodiments of the invention, the superficial velocity v used inequation 3 may be a predetermined fraction/percentage of the maximum(such as 80% of maximum). Various method of deriving v will be apparentto the skilled person, and any may be used within the scope of theinvention.

To give an example, if L is 2000 feet, v is 1 foot/day and D_(a) is1.33×10⁻⁹ m²/s (an appropriate value for NaCl in sandstone), then ifA=0.5, the average boundary layer thickness is approximately 0.5 m (1.5feet).

The effectiveness of a low salinity waterflood may be calculated using adiffusion degrade factor (F) for the reservoir. The diffusion degradefactor may be generally considered to be a measure of the ratio of thequantity of additional oil recovered when diffusion is taken intoaccount to the quantity of additional oil recovered when diffusion ofions is ignored. The “additional” oil here being the amount of oilrecovered by the low salinity waterflood compared to the preceding highsalinity waterflood.

One method of calculating this diffusion degrade factor is to comparethe total thickness of the non-boundary layers in the reservoir to thetotal thickness of the sandstone layers overall. Mathematically this canbe represented as:

$\begin{matrix}{F = \frac{\sum\left( {w_{n} - {2x}} \right)}{\sum w_{n}}} & \left( {{Equation}\mspace{14mu} 4} \right)\end{matrix}$

where, w_(n) is the thickness of a layer (each layer indexed by n) and xis the average boundary layer thickness calculated above (thecoefficient 2 appears because there are two boundary layers persandstone layer).

Equation 4 simplifies to:

$\begin{matrix}{F = {1 - \frac{2x}{H}}} & \left( {{Equation}\mspace{14mu} 5} \right)\end{matrix}$

where H is the arithmetic mean of the thicknesses of the sandstonelayers:

$\begin{matrix}{H = {\frac{1}{n}{\sum w_{n}}}} & \left( {{Equation}\mspace{14mu} 6} \right)\end{matrix}$

This equation assumes that, within the boundary layers there is noadditional oil recovery resulting from low-salinity water flooding,whereas outside the boundary layers, additional oil recovery isunaffected by salt diffusion. Equations 4 and 5 imply a negativecontribution to low salinity additional oil recovery in the presence ofdiffusion when w_(n)<2x. This may lead to an underestimation of thediffusion degrade factor F. Therefore, Equation 4 may, for example, bemodified so that it only applies when w_(n)≧2x.

A computer implemented method of determining the effectiveness ofperforming a low salinity waterflood according to an embodiment of theinvention will now be described with reference to FIG. 4. The stepsdescribed below may be performed by processor 204 executing the LSWsoftware components 209 as described above with reference to FIG. 2. Itwill be assumed below that any initialization steps required toinitialize the computer system 200, and to retrieve the LSW softwarecomponents have been performed prior to the start of the method asdescribed from step 402 below.

In step 402 data indicative of values for the interwell distance (L),diffusion coefficient (D_(a)), superficial velocity (v), and thethicknesses (w_(n)) of the sandstone layers in the reservoir is receivedby the processor.

With reference to FIG. 1, each layer has a thickness w_(n) where n is anindex for the layer (in FIG. 1, there are three layers, therefore n=1, 2or 3). Moreover, as shown in FIG. 1, layers may have variablethicknesses. Consequently, the thickness data for a layer having avariable thickness may be calculated from, for example, an averagethickness of the layer, or from a minimum thickness of the layer (otherpossibilities may be envisaged by the skilled person).

The above data may be received through interfaces 210 or 212 as shown inFIG. 2. The data may be provided from a number of sources, including areservoir model, core samples, database lookup etc. The possible sourcesof such data will be readily apparent to the skilled person.

In step 404 the processor 204 calculates an ion diffusion distance value(x) from D_(a), L, v and A. The ion diffusion distance value may, as inthis embodiment, be the average boundary layer thickness. Therefore thiscalculation may be done using equation 3 shown above, and repeated here:

$\begin{matrix}{x = {2A\sqrt{\frac{D_{a}L}{v}}}} & \left( {{Equation}\mspace{14mu} 3} \right)\end{matrix}$

In step 406, the processor 204 calculates the arithmetic mean of thethickness (represented as H) of the sandstone layers using Equation 6,reproduced here:

$\begin{matrix}{H = {\frac{1}{n}{\sum{w_{n}.}}}} & \left( {{Equation}\mspace{14mu} 6} \right)\end{matrix}$

In step 408 the processor 204 calculates a diffusion degrade factor (F)from H and x using Equation 5, reproduced here:

$\begin{matrix}{F = {1 - \frac{2x}{H}}} & \left( {{Equation}\mspace{14mu} 5} \right)\end{matrix}$

The diffusion degrade factor F may be used in a number of ways. Firstly,as shown in step 410, the diffusion degrade factor F may be used in thegeneration of an estimate for the recovery of oil from the reservoir.This may be performed by the processor 204, or the diffusion degradefactor F may be provided to a reservoir modelling system to be used ingenerating estimates of the recovery of oil. One example of this use maybe to multiply an estimate of the incremental oil recovery from the lowsalinity waterflood provided by the model by the diffusion degradefactor F, however alternative methods will be apparent to the skilledperson.

A second use of the diffusion degrade factor is described in steps 412to 418. In step 412 the diffusion degrade factor F is compared to athreshold. The threshold may have a predetermined value, which may be,for example, in the range of 0.5 to 0.9. Preferably the threshold has avalue in the range of 0.6 to 0.8. Based on the comparison, adetermination as to whether a low salinity waterflood should beperformed can be made.

Therefore, in step 414, it is determined if F is greater than thethreshold value. If F is greater, then this is taken to indicate thatthe low salinity waterflood should be performed. Alternatively, if F isless than the threshold, the low salinity waterflood is not performed.

In the method described above, the ion diffusion distance value (x) maybe calculated in step 404 from D_(a) and t. If this is the case, theprocessor may, in step 402, receive a value of t instead of the valuesof L and v. Equally, while the processor 204 is described as calculatingthe average (mean) layer thickness (H) for the reservoir, from theindividual layer thickness, it will be readily apparent that this valuemay be directly provided to the processor.

The above method may be applied to some reservoir examples, in which,L=2000 ft, v=1 ft/day, D_(a)=1.33×10⁻⁹ m²/s, and A=0.5. From these x canbe calculated as 0.48 m. Using equation 5, the diffusion degrade factorF may be calculated for a variety of different reservoirs havingdifferent layer thicknesses. The results obtained for a variety ofreservoir descriptions were compared to detailed simulations carried outwith a finite difference simulator which models the effect oflow-salinity water flooding and salt diffusion on oil recovery. Theresults are shown in FIG. 7. In this example, the best match between themethod described here and the reservoir simulation results was obtainedusing the default value of A=0.5.

In addition to determining the diffusion degrade factor F, the boundarylayer thickness x can be used to calculate a target or thresholdsuperficial velocity for the low salinity waterflood. This may be of usesince, as mentioned above, the superficial velocity of the waterfloodmay be varied by varying e.g. the injection pressure, thereforeproviding a target, or a minimum velocity threshold, the effectivenessof the low salinity waterflood can be assured.

Firstly, by combining Equations 3 and 5, reproduced here:

$\begin{matrix}{x = {2A\sqrt{\frac{D_{a}L}{v}}}} & \left( {{Equation}\mspace{14mu} 3} \right) \\{F = {1 - \frac{2x}{H}}} & \left( {{Equation}\mspace{14mu} 5} \right)\end{matrix}$

A relationship between the superficial velocity v and the degrade factorF can be established, specifically:

$\begin{matrix}{{H\left( {1 - F} \right)} = {{2x} = {4A\sqrt{\frac{D_{a}L}{v}}}}} & \left( {{Equation}\mspace{14mu} 7} \right)\end{matrix}$

Equation 7 can be rearranged to produce Equation 8:

$\begin{matrix}{v = {16\frac{D_{a}{LA}^{2}}{{H^{2}\left( {1 - F} \right)}^{2}}}} & \left( {{Equation}\mspace{14mu} 8} \right)\end{matrix}$

It is desirable to ensure that the velocity is sufficiently high tomaintain the diffusion degrade factor F at, around, or above a desiredtarget or limit. Therefore, taking F_(target) as the target value forthe diffusion degrade factor F the target velocity v_(target) can bederived as:

$\begin{matrix}{v_{target} = {16\frac{D_{a}{LA}^{2}}{{H^{2}\left( {1 - F_{target}} \right)}^{2}}}} & \left( {{Equation}\mspace{14mu} 8a} \right)\end{matrix}$

The target velocity v_(target) may then be used in the control of theinjection well to ensure that the superficial velocity of the waterfloodis kept at, around, or above the target. Various method of doing thiswill be apparent to the skilled person, for example, the superficialvelocity may be kept within a predetermined range around or above thetarget velocity v_(target), alternatively the superficial velocity maybe controlled to always be above the target velocity v_(target) withother factors (if required) determining a maximum velocity.

As mentioned above, the diffusion degrade factor F represents theproportion of additional oil recovered by the low salinity waterfloodingwith diffusion taken into account against the case where diffusion ofions is ignored. As such, it represents a measure of the potentialsuccess of the waterflooding. Consequently, the target value for thediffusion degrade factor F_(target) may be used to represent a minimumacceptable or ideal value which should be achieved for the waterfloodingto be successful (whether practically, in terms of e.g. the amount oflow salinity water available, or economically). As a consequence,maintaining the velocity of the waterflood to be above or at the targetvelocity will ensure that the effectiveness of the waterflood is equallyabove or at the target.

A computer implemented method of controlling a low salinity waterfloodaccording to an embodiment of the invention will now be described withreference to FIG. 5. As described above with reference to FIG. 4, thesteps below may be performed by processor 204 while executing the LSWsoftware components 209.

In step 502 the processor receives data indicative of the interwelldistance (L), diffusion coefficient (D_(a)), the mean layer thickness(H), the constant (A), and the target diffusion degrade factor(F_(target)). As described above, the mean layer thickness (H) may bereceived directly, or calculated from the individual layer thicknesses(w_(n)).

In step 504 the processor 204 calculates a target superficial velocity(v_(target)) from D_(a), L, H and F_(target). This may be done usingequation 8.

The target superficial velocity may then be used to control theinjection pressure in the injection well to thereby control thesuperficial velocity of the waterflood within the reservoir.Consequently, in step 506, the processor 204 may transmit an indicationof the target superficial velocity to the injection well using interface212.

Subsequently in step 508, the control systems in the injection wellcontrol the injection well to maintain the superficial velocity of theflood at an appropriate speed in view of the target superficialvelocity. This may be done in any number of ways, which will be obviousto the skilled person, and may be done by maintaining the averagesuperficial velocity of the injection fluid at the target superficialvelocity, or by ensuring that the superficial velocity of the flood iskept above the target superficial velocity.

Finally, a computer implemented method of determining the locations ofthe production injection wells according to an embodiment of theinvention will be described with reference to FIG. 6.

As described above with reference to Equations 8 and 8a, a targetsuperficial velocity may be derived. Equation 8 may be rearranged sothat a target interwell length can be derived. Specifically equation 8can be rearranged as:

$\begin{matrix}{L = \frac{{H^{2}\left( {1 - F} \right)}^{2}v}{16D_{a}A^{2}}} & \left( {{Equation}\mspace{14mu} 9} \right)\end{matrix}$

which provides the target length as:

$\begin{matrix}{L_{target} = \frac{{H^{2}\left( {1 - F_{target}} \right)}^{2}v}{16D_{a}A^{2}}} & \left( {{Equation}\mspace{14mu} 9a} \right)\end{matrix}$

This target length L_(target) may be calculated from a average value forthe superficial velocity (v) as discussed above.

Therefore, with reference to FIG. 6, in step 602 the processor 204receives data indicative of the diffusion coefficient (D_(a)), thesuperficial velocity (v), the mean layer thickness (H), the constant(A), and the target diffusion degrade factor (F_(target)). The meanlayer thickness (H) may be received directly, or calculated from theindividual layer thicknesses (w_(n)).

From these values, using Equation 9, the processor 204 derives a targetinterwell length (L_(target)). This length, being a target, mayrepresent a maximum value for the interwell length, or may represent thecentre point for a desired range of interwell lengths (for example,L_(target)±10%).

In step 706 the processor 204 may output the target interwell length(L_(target)). In a similar manner to that described above, the valueL_(target) may be output using the interfaces 210 and 212. Alternativelythe value L may be used directly by the processor 204.

Finally, in step 706, the target interwell length (L_(target)) is usedin locating the wells penetrating the reservoir. The wells may belocated such that the interwell length is less than the target length,or is within a predetermined factor of the length. The exact mechanismto locate the wells which is to be used will depend on a number of otherfactors, however the target interwell length can be considered as aguide to ensure that low salinity waterflooding will be a possibilitywhen the wells are in production (for the reasons stated above). Thisstep may be performed by processor 204; however it equally may beperformed by a separate processing system which is tasked withdetermining well locations.

In the foregoing embodiments of the invention, the calculations aredescribed as being performed in the processing unit 202, however this isnot a requirement. Equally, while the processing unit has been describedas a single, stand-alone, unit, this may not be the case, and forexample the functionality of the processing unit may be incorporatedinto any other entity, or be distributed across a number of entities.The LSW software components are described as being stored in the memory208, however the LSW software components may alternatively be receivedvia the network interface 212 (from e.g. a remote database). The outputsmay be provided to various other entities, such as the well controlapparatus. The mechanisms by which this may be done will be well knownto the skilled person.

Additional Details and Modifications

While the above embodiments have been described in relation to thediffusion degrade factor F, which defines the ratio of oil recovery withand without diffusion, it will be apparent that an alternative“diffusion loss factor” (G) may be use which defines the ratio of ‘lost’oil to the total oil recovery. Consequently, G may be defined asG=1−F=2x/H. It will be apparent that G and F have a very simplerelationship; therefore, the skilled person would have no difficulty inusing either in embodiments of the invention.

While one method of determining and using a boundary layer thickness hasbeen described above, other possibilities are envisaged withoutdeparting from the scope of the invention.

For example, the layers may be categorized as either “marginal facies”or “axial facies”. This may be done using the boundary layer thickness.For example, “marginal facies” may denote interbedded sandstone andshale layers where the sandstone layers are strongly affected bydiffusion of salt ions, and in view of the above, may be defined aslayers having a thickness comparable to, or thinner than, twice theboundary layer thickness x (meaning that the entire sandstone layer isdefined as being boundary layer). By contrast, the “axial facies” areinterbedded sandstone layers where the sandstone layers are thicker thanfour times this boundary layer thickness x. The threshold used tocategorize these layers (4x above) may take other values, such as 5x or6x. Having classified the layers, a diffusion degrade factor may then bedetermined based on the aggregate thickness of the thick (axial) layersto the total thickness of all the layers.

It will be apparent that Equation 5 will tend to underestimate thediffusion degrade factor in cases where there are many layers of athickness less than twice the boundary layer thickness (since two fullboundary layers are assumed to exist for each layer, irrespective ofwhether the layer is too thin to be able to contain two such layers—andfor layers of a thickness less than twice the boundary layer thickness,the boundary layers will effectively be assumed to overlap).

Consequently, the method may be adapted to take this into account. Onemethod by which this may be done is to define an effective non-boundarythickness (e_(n)) for each layer which takes into account this overlap,i.e.:

$\begin{matrix}{e_{n} = \left\{ \begin{matrix}{w_{n} - {2x}} & {w_{n} > {4x}} \\\frac{w_{n}^{2}}{8x} & {w_{n} \leq {4x}}\end{matrix} \right.} & \left( {{Equation}\mspace{14mu} 9} \right)\end{matrix}$

from e_(n), the diffusion degrade factor F can be calculated using amodified version of Equation 4 as follows:

$\begin{matrix}{{F = \frac{\sum e_{n}}{\sum w_{n}}},{\forall n}} & \left( {{Equation}\mspace{14mu} 10} \right)\end{matrix}$

In Equation 10, the diffusion degrade factor F is therefore the sum ofthe effective thicknesses divided by the sum of the layer thicknesses.

In the above examples, the “apparent diffusion coefficient” has beenused to define the rate of diffusion of the ions through the sandstone.However, the skilled person will recognize that there are a number ofdifferent types of diffusion coefficient which might be used. Forexample: a bulk diffusion coefficient relates to the diffusion of ionsin a bulk liquid; a pore diffusion coefficient takes into account thetortuosity of the pores in the sandstone which constrain the diffusion;finally the apparent diffusion coefficient takes into account bothtortuosity and sorbtion of ions. For a non-sorbing ion, the porediffusion coefficient is the same as the apparent diffusion coefficient,however this is not the case for a sorbing ion. The skilled person willtherefore understand that any appropriate diffusion coefficient may beused in embodiments of the invention without departing from the scope ofthe claims.

Equally, the above described methods are related to salt ions which arenon-sorbant in sandstone. However it will be apparent to the skilledperson that the invention may be adapted to ions which are sorbant insandstone (with appropriate adaptation of the diffusion coefficient).

The salt diffusivities in shale can be determined experimentally with asufficient degree of accuracy to determine the effect of salt diffusionon the incremental oil recovery that can be achieved with a low salinitywaterflood. Since the rate of salt diffusion is proportional to theconcentration gradient between the high salinity connate water containedin the pore space of the shale layer and the low salinity water that isflowing through the pore space of an adjacent sandstone layer, it isimportant to determine the salinity of the connate water that is presentin the shale layers together with the concentrations of the individualionic (salt) species in this connate water, in particular, theconcentration of the various multivalent cations together with the totalconcentration of multivalent cations in this connate water.

Consequently, samples of the connate water that is present in the porespace of the sandstone layers and in the pore space of the interbeddedshale layers may be obtained by taking a core sample from the reservoirthrough the different reservoir layers. From these the TDS andmultivalent cation content of the water contained within the differentlayers of the core may then be determined.

The low salinity water that is injected into the sandstone layers of theoil reservoir may have a total dissolved solids (TDS) content in therange of 200 to 12,000 ppm, preferably, 500 to 10,000 ppm. Where theformation rock contains swelling clays, in particular, smectite clays, arelatively high TDS for the low salinity water is required in order tostabilize the clays, thereby avoiding the risk of formation damage.Thus, where the formation rock contains an amount of swelling clayssufficient to result in formation damage, the low salinity water that isinjected into the oil-bearing formation preferably has a TDS content inthe range of 8,000 to 12,000 ppm. Where the formation comprises amountsof swelling clays that do not result in formation damage, the TDScontent of the low salinity water is typically in the range of 200 to8,000 ppm, preferably 500 to 8,000 ppm, and for example may be 1,000 to5,000 ppm. In this context, it is observed that an overall increase inthe salinity of the low salinity water may be tolerated provided thatthe salinity of the low salinity water remains within the desired rangefor the low salinity waterflood.

The concentration gradient between the connate water that is present inthe shale layer and the low salinity injection water that is flowingthrough an adjacent sandstone layer is particularly significant when theconnate water of the shale layer has a TDS of at least 100,000 ppm,especially, at least 200,000 ppm, for example, is in the range of150,000 to 400,000 ppm, in particular, 150,000 to 250,000 ppm.

The incremental oil recovery that is achieved for a low salinitywaterflood is dependent upon the ratio of the total multivalent cationcontent in the low salinity injection water that is injected into thesandstone layers of the reservoir to the total multivalent cationcontent in the connate water that is present in the pore space of thesandstone layers of the reservoir (hereinafter “multivalent cationratio”). It has previously been found that this multivalent cation ratioshould be less than 1, for example, less than 0.9. Generally, the lowerthe multivalent cation ratio the greater the amount of oil that isrecovered from the reservoir. Thus, the multivalent cation ratio ispreferably less than 0.8, more preferably, less than 0.6, yet morepreferably, less than 0.5, and especially less than 0.4 or less than0.25. The multivalent cation ratio may be at least 0.001, preferably, atleast 0.01, most preferably, at least 0.05, in particular at least 0.1.Preferred ranges for the multivalent cation ratio are 0.01 to 0.9, 0.05to 0.8, but especially 0.05 to 0.6 or 0.1 to 0.5. The ratio of the totaldivalent cation content of the said low salinity injection water to thetotal divalent cation content of the formation water that is present inthe sand layers of the reservoir (hereinafter “divalent cation ratio”)should also less than 1. The preferred values and ranges for themultivalent cation ratio may be applied mutatis mutandis to the divalentcation ratio.

Typically, the calcium content of the low salinity injection water is inthe range of 1 to 100 ppm, preferably 5 to 50 ppm. Typically, themagnesium content of the low salinity injection water is in the range of5 to 100, preferably 5 to 30 ppm. The barium content of the low salinityinjection water may be in the range of 0.1 to 20, such as 1 to 10 ppm.Typically, the total content of multivalent cation in the low salinityinjection water is 1 to 200 ppm, preferably 3 to 100, especially 5 to 50ppm with the proviso that the multivalent cation ratio is less than 1.

Accordingly, diffusion of multivalent cations from the connate watercontained in the pore space of a shale layer into the low salinity waterthat is flowing through an adjacent sandstone layer of the reservoir isof concern if this results in an increase the “multivalent cation ratio”or the “divalent cation ratio” to above 1.

Typically, the multivalent cation content of the connate water that iscontained in the pore space of the shale layer is in the range of 7,500to 50,000 ppm, in particular, 10,000 to 30,000 ppm, with highermultivalent cation concentrations being associated with higher salinityconnate waters.

The apparent diffusivities of non-sorbing ions in sandstone rock may bedetermined using the following methodology. In sandstone, the effectivediffusivity is:

$D_{e} = {\frac{D_{0}\varphi}{F\; \varphi^{1 - m}} = {D_{0} \cdot \varphi^{m}}}$

wherein D₀ is the bulk diffusivity in aqueous solution, Φ is theporosity of the sandstone rock, m is the Archie ‘cementation factor’,and F is the formation resistance factor. For a typical sandstone rock,the cementation factor, m, lies within the range of 1.7 to 2.7. If D₀ istaken to be 3.1×10⁻⁹ m²/s (this is the value for the harmonic mean ofbulk diffusivity of Na⁺ and Cl⁻ ions at a temperature of 132.8° F.),then for a sandstone rock having a porosity of 0.3, the effectivediffusivity, D_(e), lies within the range of 1×10¹⁰ to 4×10⁻¹⁰ m²/s forthe stated range of m. Accordingly, the apparent diffusivity,D_(a)=D₀·φ^(m−1), for a non-sorbing ion (such as Na⁺ or Cl⁻) lies withinthe range of 4×10⁻¹⁰ to 1.33×10⁻⁹ m²/s for the stated range of m.

The following relationships between the chemical characteristics of theconnate water contained in the pore space of the shale layers and thechemical characteristics of the injected low salinity water may have animpact on the incremental oil recovery that is achieved with a lowsalinity waterflood:

(a) the difference in TDS between the low salinity water that isinjected into the sandstone layers of the reservoir and the connatewater of an interbedded shale layers;

(b) the difference between the multivalent cation concentration of thelow salinity water that is injected into the sandstone layers of thereservoir and the multivalent cation concentration of the connate waterof an interbedded shale layer.

Thus, as discussed above, the connate water of the shale layer has botha higher TDS and a higher multivalent cation content than the lowsalinity water that is injected into the sandstone layers of thereservoir. The above described embodiments of the invention allow forthe diffusion of the non-sorbant ions, however these methods may becombined with methods to allow for the effects of TDS in the shalelayers.

The thickness of the interbedded shale layers may be of significance asthis determines the total amount of salt ions available for diffusionfrom an interbedded shale layer into the low salinity water that isflowing through an adjacent sandstone layer. In reservoirs havingrelatively thin interbedded shale layers, the amount of salt ionsavailable for diffusion into the interbedded sandstone layers may below. Therefore, it is envisaged that the thickness of the shale layersmay be taken into account in the calculations above, insofar as thinshale layers can no longer be approximated as an unlimited supply ofions.

It is to be understood that any feature described in relation to any oneembodiment may be used alone, or in combination with other featuresdescribed, and may also be used in combination with one or more featuresof any other of the embodiments, or any combination of any other of theembodiments. Furthermore, equivalents and modifications not describedabove may also be employed without departing from the scope of theinvention, which is defined in the accompanying claims. The features ofthe claims may be combined in combinations other than those specified inthe claims.

1-30. (canceled)
 31. A computer-implemented method for determining theeffectiveness of performing a low salinity waterflood on ahydrocarbon-bearing reservoir, wherein the reservoir comprisesrelatively permeable layers interbedded with relatively impermeablelayers and is penetrated by an injection well and a production well, thelow salinity waterflood comprising injecting low salinity water into thehydrocarbon-bearing reservoir from the injection well whereby to passthrough the relatively permeable layers of the reservoir from theinjection well to the production well, and wherein the relativelyimpermeable layers have a relatively high concentration of ions comparedto that of the relatively permeable layers when the low salinity wateris present therein, the method comprising: deriving an ion diffusiondistance value from: a diffusion coefficient indicative of a rate ofdiffusion of ions through the relatively permeable layers when the lowsalinity water is present therein; and a residence time value indicativeof the time required for the low salinity water to pass from theinjection well to the production well through the reservoir; comparingthe thickness of the relatively permeable layers to the derived iondiffusion distance value; and using a result of the comparison togenerate an output indicative of the effectiveness of performing a lowsalinity waterflood.
 32. The method of claim 31, comprising: determiningan average thickness of the relatively permeable layers; and calculatinga ratio of the ion diffusion distance value to the average thickness,whereby to compare the thickness of the relatively permeable layers tothe derived ion diffusion distance value.
 33. The method of claim 32,wherein an output value based on the calculated ratio is output wherebyto generate the output indicative of the effectiveness of performing alow salinity waterflood.
 34. The method of claim 33, wherein the outputvalue is calculated from $1 - \frac{x}{H}$ where x is the ion diffusiondistance value and H is said average thickness.
 35. The method of claim31, wherein the residence time value is calculated from an interwelldistance between the injection well and the production well, and avelocity at which the low salinity water passes through the reservoir.36. The method of claim 35, wherein the ion diffusion distance value isdetermined from 2A√(D_(a)Lv⁻¹) wherein D_(a) is the apparent diffusioncoefficient for ions in the relatively permeable layers, L is theinterwell distance between the injection well and production well, v isthe velocity of the low salinity water through the reservoir, and A is aconstant.
 37. The method of claim 36, wherein the predetermined constantA has a value in the range of 0.125-2 and preferably has a value of 0.5.38. The method of claim 35, wherein the velocity of the low salinitywater through the reservoir is indicative of superficial velocity of thelow salinity water through the relatively permeable layers.
 39. Themethod of claim 31, wherein the residence time value for the lowsalinity water in the reservoir is measured using a tracer injected intothe reservoir by the injection well.
 40. The method of claim 31,comprising using the output indicative of the effectiveness ofperforming a low salinity waterflood to calculate an estimate for therecovery of hydrocarbons from the reservoir.
 41. The method of claim 31,wherein the relatively permeable layers comprise sandstone layers, andthe relatively impermeable layers comprise shale layers.
 42. Acomputer-implemented method of controlling a low salinity waterflood fora hydrocarbon-bearing reservoir, wherein the reservoir comprisesrelatively permeable layers interbedded with relatively impermeablelayers and is penetrated by an injection well and a production well, thelow salinity waterflood comprising injecting low salinity water into thehydrocarbon-bearing reservoir from the injection well whereby to passthrough the relatively permeable layers of the reservoir from theinjection well to the production well, and wherein the relativelyimpermeable layers have a relatively high concentration of ions comparedto that of the relatively permeable layers when the low salinity wateris present therein, the method comprising: deriving a target velocitybased on: a diffusion coefficient indicative of a rate of diffusion ofions through the relatively permeable layers when the low salinity wateris present therein; an interwell distance between the injection well andthe production well; and a value indicative of a thickness of therelatively permeable layers; and transmitting the derived targetvelocity to a control unit of an injection well.
 43. The method of claim42, comprising controlling a velocity at which the low salinity waterpasses through the relatively permeable layers based on the targetvelocity.
 44. The method of claim 43, comprising controlling the fluidflow through the injection well whereby to control the velocity at whichthe low salinity water passes through the relatively permeable layers.45. The method of claim 42, wherein the target velocity is determinedfrom$16\frac{D_{a}{LA}^{2}}{{H^{2}\left( {1 - F_{target}} \right)}^{2}}$wherein D_(a) is the apparent diffusion coefficient for ions in therelatively permeable layers, L is the interwell distance between theinjection well and production well, H is a value indicative of anaverage thickness of the relatively permeable layers, A is a constantand F_(target) is a predetermined target diffusion degrade factor. 46.The method of claim 45, wherein the constant A has a value in the rangeof 0.125 to 2 and preferably has a value of 0.5.
 47. The method of anyof claim 42, wherein predetermined target diffusion degrade factorF_(target) is a measure of a target effectiveness of the low salinitywaterflood.
 48. The method of claim 47, wherein the predetermined targetdiffusion degrade factor F_(target) has a value between 0.6 and 0.9. 49.The method of claim 42, comprising maintaining an average velocity atwhich the low salinity water passes through the relatively permeablelayers to be at or above the target velocity whereby to control thevelocity at which the low salinity water passes through the relativelypermeable layers.
 50. The method of claim 42, comprising maintaining aminimum velocity at which the low salinity water passes through therelatively permeable layers to be above the target velocity whereby tocontrol the velocity at which the low salinity water passes through therelatively permeable layers.
 51. The method of claim 42, wherein therelatively permeable layers comprise sandstone layers, and therelatively impermeable layers comprise shale layers.
 52. Acomputer-implemented method of determining locations of at least oneproduction well and at least one injection well for ahydrocarbon-bearing reservoir, wherein the reservoir comprisesrelatively permeable layers interbedded with relatively impermeablelayers and is to be penetrated by the at least one injection well and atleast one production well, wherein the injection well is arranged toprovide a low salinity waterflood comprising injecting low salinitywater into the hydrocarbon-bearing reservoir from the injection wellwhereby to pass through the relatively permeable layers of the reservoirfrom the injection well to the production well, and wherein therelatively impermeable layers have a relatively high concentration ofions compared to that of the relatively permeable layers when the lowsalinity water is present therein, the method comprising: calculating aninterwell distance value based on: a diffusion coefficient indicative ofa rate of diffusion of ions through the relatively permeable layers whenthe low salinity water is present therein; a value indicative of athickness of the relatively permeable layers; and a velocity at whichthe low salinity water passes through the reservoir; and using theinterwell distance value to determine the locations of the at least oneinjection well and the at least one production well such that theinterwell distance between the said at least one injection well and atleast one production well is less than said interwell distance value.53. The method of claim 52, wherein the interwell distance value isdetermined from$\frac{{H^{2}\left( {1 - F_{target}} \right)}^{2}v}{16D_{a}A^{2}}$wherein D_(a) is the apparent diffusion coefficient for ions in therelatively permeable layers, H is a value indicative of an averagethickness of the relatively permeable layers, A is a constant, v is avelocity of the low salinity water through the reservoir, and F_(target)is a predetermined target diffusion degrade factor.
 54. The method ofclaim 53, wherein the constant A has a value in the range of 0.2 to 2and preferably has a value of
 1. 55. The method of claim 53, whereinpredetermined target diffusion degrade factor F_(target) is a measure ofa target effectiveness of the low salinity waterflood.
 56. The method ofclaim 55, wherein the predetermined target diffusion degrade factorF_(target) has a value between 0.6 and 0.9.
 57. The method of claim 52,wherein the relatively permeable layers comprise sandstone layers, andthe relatively impermeable layers comprise shale layers.
 58. A computerreadable storage medium storing computer readable instructions thereonfor execution on a computing system to implement a method fordetermining the effectiveness of performing a low salinity waterflood ona hydrocarbon-bearing reservoir, wherein the reservoir comprisesrelatively permeable layers interbedded with relatively impermeablelayers and is penetrated by an injection well and a production well, thelow salinity waterflood comprising injecting low salinity water into thehydrocarbon-bearing reservoir from the injection well whereby to passthrough the relatively permeable layers of the reservoir from theinjection well to the production well, and wherein the relativelyimpermeable layers have a relatively high concentration of ions comparedto that of the relatively permeable layers when the low salinity wateris present therein, the method comprising: deriving an ion diffusiondistance value from: a diffusion coefficient indicative of a rate ofdiffusion of ions through the relatively permeable layers when the lowsalinity water is present therein; and a residence time value indicativeof the time required for the low salinity water to pass from theinjection well to the production well through the reservoir; comparingthe thickness of the relatively permeable layers to the derived iondiffusion distance value; and using a result of the comparison togenerate an output indicative of the effectiveness of performing a lowsalinity waterflood.
 59. A computer readable storage medium storingcomputer readable instructions thereon for execution on a computingsystem to implement a computer-implemented method of controlling a lowsalinity waterflood for a hydrocarbon-bearing reservoir, wherein thereservoir comprises relatively permeable layers interbedded withrelatively impermeable layers and is penetrated by an injection well anda production well, the low salinity waterflood comprising injecting lowsalinity water into the hydrocarbon-bearing reservoir from the injectionwell whereby to pass through the relatively permeable layers of thereservoir from the injection well to the production well, and whereinthe relatively impermeable layers have a relatively high concentrationof ions compared to that of the relatively permeable layers when the lowsalinity water is present therein, the method comprising: deriving atarget velocity based on: a diffusion coefficient indicative of a rateof diffusion of ions through the relatively permeable layers when thelow salinity water is present therein; an interwell distance between theinjection well and the production well; and a value indicative of athickness of the relatively permeable layers; and transmitting thederived target velocity to a control unit of an injection well.
 60. Acomputer readable storage medium storing computer readable instructionsthereon for execution on a computing system to implement acomputer-implemented method of determining locations of at least oneproduction well and at least one injection well for ahydrocarbon-bearing reservoir, wherein the reservoir comprisesrelatively permeable layers interbedded with relatively impermeablelayers and is to be penetrated by the at least one injection well and atleast one production well, wherein the injection well is arranged toprovide a low salinity waterflood comprising injecting low salinitywater into the hydrocarbon-bearing reservoir from the injection wellwhereby to pass through the relatively permeable layers of the reservoirfrom the injection well to the production well, and wherein therelatively impermeable layers have a relatively high concentration ofions compared to that of the relatively permeable layers when the lowsalinity water is present therein, the method comprising: calculating aninterwell distance value based on: a diffusion coefficient indicative ofa rate of diffusion of ions through the relatively permeable layers whenthe low salinity water is present therein; a value indicative of athickness of the relatively permeable layers; and a velocity at whichthe low salinity water passes through the reservoir; and using theinterwell distance value to determine the locations of the at least oneinjection well and the at least one production well such that theinterwell distance between the said at least one injection well and atleast one production well is less than said interwell distance value.